Hydrodesulfurization utilizing multiple hydrogen recycle streams

ABSTRACT

A portion of the effluent gas from a hydro-desulfurization process is treated for removal of hydrogen sulfide and admixed with the hydrocarbon fraction before entry into the feed heater. Untreated effluent gas containing hydrogen and hydrogen sulfide is then admixed with the preheated hydrocarbon-hydrogen gas mixture prior to entry into the reactor. Treating only that portion of the effluent gas which passes through the heater minimizes coking and corrosion problems in the heater but it also reduces the effort previously required for treating all the recycle gas.

United States Patent 3,676,333 Carlson et al. 1 1 July 11, 1972 s41HYDRODESULFURIZATION UTILIZING 2,840,513 6/1958 Nathan ..208/209MULTIPLE HYDROGEN RECYCLE 3,563,887 2/1971 Fraser et a1 ..208/2l6STREAMS 3,362,903 1/1968 Eastman et al .....208/2l3 2,902,440 9/1959Beuther et al. .....208/2l0 [72] Inventors: Edgar Carlson, Allison Park,Pa.; William 2,937,134 5/1960 Bowles ..208/210 R. Lehrian, Tokyo, JapanPrimary ExaminerDelbert E. Gantz [73] Asslgnee: Research DevelopmentCmnpany, Assistant ExaminerG. J. Crasanakis Pmsburgh, Attorney-MeyerNeishloss, Deane E. Keith and Thomas G. 221 Filed: March 26,1970 Ryde"[2]] Appl. No.: 25,115 [57] ABSTRACT A portion of the effluent gas froma hydro-desulfurization [52] U.S.Cl ..208/209 process is treated forremoval of hydrogen sulfide and ad- [51] lnt.Cl ..Cl0g 23/00 mixed iththe hydrocarbon fraction before e t y into the [58] Field of Search..208/209, 21 1, 212, 216, 213, feed heater- Untreated emuent gcontaining hydr g n and 208/210 217 hydrogen sulfide is then admixedwith the preheated hydrocarbon-hydrogen gas mixture prior to entry intothe [56] Reta-cum Cited reactor. Treating only that portion of theeffluent gas which passes through the heater minimizes coking andcorrosion UNITED STATES PATENTS problems in the heater but it alsoreduces the effort previously required for treating all the recycle gas.2,920,033 1/1960 Beavon ..208/209 2,755,225 7/1956 Porter et al...208/211 7 Claims, 1 Drawing Figure FA? 56 5a PATENTEDJUL 11 1972 3, 676.333

W/LL 64M R. LEHR/A/V I-IYDRODESULFURIZATION UTILIZING MULTIPLE HYDROGENRECYCLE STREAMS This invention relates to a novel hydrocarbondesulfurization process. More particularly, this invention relates to ahydrocarbon desulfurization process wherein a high purity hydrogensulfide by-product stream is recovered.

Hydrocarbon fractions that contain sulfur have been conventionallysubjected to a catalytic desulfurization treatment in the presence ofhydrogen. Unreacted hydrogen, along with hydrogen sulfide and othernon-condensible gases formed in the desulfurization reaction, iscontained in the reaction effluent. It is highly desirable to separatethe hydrogen from the reaction effiuent stream for recycle to thereaction zone. The hydrogen sulfide and other non-condensible gas shouldbe separated from the hydrodesulfurized product in order to preventequipment corrosion and contamination of the hydrocarbon product.

In order to recover a hydrocarbon product substantially free of hydrogensulfide, it has been proposed to cool the entire desulfurizationreaction effluent to a sufficiently low temperature in order to condensethe major portion of the hydrocarbon product and permit a separationthereof into a liquid fraction and a vapor fraction. The liquid fractionand the vapor fraction are separately treated for the removal ofhydrogen sulfide and the remaining portion of the vapor fraction, whichconsists essentially of hydrogen, is recycled to thehydrodesulfurization reaction zone.

In hydrodesulfurization processes, it is essential that the totalrecycle gas stream be treated to remove hydrogen sulfide when thepartial pressure of the hydrogen sulfide is high enough to cause severecorrosion in the furnace or heater employed to heat the hydrocarboncharge stock to the proper temperature for the desulfurization reaction.An amine solution, e.g., diethanolamine, triethanolamine, etc., haspreviously been employed for the removal of hydrogen sulfide from therecycle gas stream. However, as the process pressure is increased,hydrocarbons present in the recycled gas stream are partially removed inthe hydrogen sulfide treater along with the hydrogen sulfide product.The presence of such hydrocarbons is highly undesirable in the hydrogensulfide product when the hydrogen sulfide is employed as a charge stockto a sulfur production unit since the presence of excessive hydrocarbonsalong with the hydrogen sulfide will cause the production of a black andunsalable sulfur. This is particularly true of hydrocarbons containingin excess of three carbon atoms per molecule.

As the process pressure is increased, the amount of hydrocarbons per molof hydrogen sulfide removed by the treating agent will increase. Inaddition, the hydrocarbon contaminants can be present in quantitiesgreater than solubility data would predict by means of condensationand/or entrainment in the recycle gas. Condensation and entrainment canbe reduced by design. However, solubility is a natural effect and cannotbe reduced or eliminated by design.

It has now been found that a hydrogen sulfide by-product for use as feedto a sulfur unit can be produced which is substantially reduced in itsheavy hydrocarbon content and severe corrosion in thehydrodesulfurization feed heater can be eliminated by thedesulfurization process of the present invention, which comprisespassing a hydrocarbon charge stock to a hydrodesulfurization zone,separating a gaseous hydrogen sulfide-containing effluent stream fromthe effluent of the hydrodesulfurization zone, subjecting a portion ofthe gaseous stream to a hydrogen sulfide removal treatment so as toproduce a substantially hydrogen sulfide-free gaseous stream, andrecycling the remaining portion of the gaseous stream for admixture withthe hydrocarbon charge stock to the hydrodesulfurization treatment.

We have found that by passing only a portion of the hydrogensulfide-containing gas stream to the hydrogen sulfide removal treatmentand recycling the purified hydrogen stream, sufficient hydrogen sulfideis removed from the recycle gas stream that severe corrosion will notresult in the feed heater, while at the same time the amount ofhydrocarbons removed along with the hydrogen sulfide in the hydrogensulfide removal zone is sufficiently small that a salable sulfurbyproduct can be produced from the recovered hydrogen sulfide. Thesubstantially hydrogen sulfide-free stream is admixed with thehydrocarbon charge stock prior to being passed through the preheater soas to provide sufficient hydrogen in order to prevent excessive cokingin the desulfurization feed heater. Untreated gaseous effluent streamfrom the desulfurization treatment is recycled for admixture with thehydrocarbon charge stock to the desulfurization treatment after thecharge stock has been preheated.

In order to more fully understand the nature of the present process,reference is made to the accompanying drawing which is substantially aschematic diagram of a process which embodies the present invention.

Referring to the drawing, a sulfur-containing hydrocarbon fraction, suchas a naphtha, furnace oil, cracking charge stock, shale oil, coke-ovenoil, residual-containing hydrocarbons such as whole or reduced crude andthe like, is fed via line 10 and is admixed with make-up hydrogen, whichis introduced by means of the line 12, and treated recycle hydrogen,which is introduced by means of the line 14. The hydrogen-hydrocarbonadmixture is passed to a gas-fired heater 16. If the hydrocarbonfraction which is introduced by means of the line 10 is a whole crude"or the like, it is preferably separated from water or sediment and isdesalted, but need not be processed in any other manner.

The hydrogen-hydrocarbon admixture is heated in the furnace 16 to atemperature suitable for catalytic desulfurization. For example,suitable temperatures for desulfurization include those in the range ofbetween about 500 and about 900 F., preferably between about 700 andabout 850 F. The makeup hydrogen stream 12 contains high purity hydrogenand comprises, for example, about 93 percent hydrogen by volume. Therecycled hydrogen stream 14 will contain some hydrogen sulfide; however,the amount of hydrogen sulfide is sufficiently low that corrosion willnot occur in the heater 16 to any substantial degree. Accordingly, therecycled gas stream is a desulfurization reactor effluent stream thathas been treated for hydrogen sulfide removal, e.g., by amine treatment.Otherwise, the hydrogen sulfide partial pressure in the recycled gasstream is high enough to cause severe corrosion problems in the feedheater when the heater is fabricated from normal materials ofconstruction.

Sufficient hydrogen-containing recycled gas must be added to thehydrocarbon feed to the heater along with the make-up hydrogen toprevent excessive coking in the feed heater. Thus, for example,sufficient recycle gas is admixed with the makeup hydrogen to provideabout 1500 standard cubic feet of hydrogen per barrel of hydrocarbonfeed to the feed heater 16.

After the hydrogen-hydrocarbon admixture has been heated to atemperature suitable for desulfurization, additional recycle hydrogencan be added to the admixture by means of the line 18. This additionalrecycle hydrogen stream has been preheated by heat exchange with areactor effluent stream but has not been treated for removal of hydrogensulfide. The desulfurization charge stock may now be passed to catalystguard beds (not shown), if desired, for the removal of impurities thatare detrimental to the desulfurization catalyst. The preheated stream ispassed by means of the line 20 to a desulfurization reactor 22, which isprovided with one or more beds of a conventional desulfurizationcatalyst.

Suitable desulfurization catalysts include metals of Group VIA (e.g.,molybdenum and tungsten), Group VIll (e.g., iron, cobalt, nickel) of thePeriodic Chart, their oxides or sulfides, alone, or in admixture, andpreferably provided on a noncracking support such as alumina, bauxiteand the like. Specific examples of such catalysts include, NiCo-Mo onalumina, Co-Mo on alumina, sulfided NiW on alumina, and the like.

The hydrodesulfurization reaction can be conducted at a temperature, forexample, in the range of between about 500 and about 900 F preferablybetween about 700 and about 850 F. Suitable pressures for thedesulfurization reactor are between about 250 and about 4,000 psig,preferably between about 500 and about 3,000 psig. The liquid hourlyspace velocity (LHSV) employed is in the range of between about 0.25 andabout 16, preferably between about 0.5 and about 2.0. The term liquidhourly space velocity as employed herein refers to the volume ofdesulfurization feed (measured at 60 F.) per hour per volume of catalystemployed. Hydrogen is passed along with the hydrocarbon feed to thereactor 22 at a rate of between about 200 and about 20,000 standardcubic feet per barrel of hydrocarbon charge, preferably between about5,000 and about 10,000 standard cubic feet per barrel.

The desulfurized reactor effluent is discharged from the reactor 22 bymeans of the line 24. This stream can be heat exchanged with a recyclehydrogen gas stream in heat exchange means 38, and/or heat exchangedwith the feed to the hydrodesulfurization reactor and/or the crude feed(by a means not shown). Next, the temperature of the reactor effluent isfurther reduced by a suitable heat exchange means such as an aerialcooler 26. The cooled effluent is then passed by means of conduit 27 toa flash drum 28 for the separation of liquid from vapor. The flash drum28 is a high pressure flash drum and may be operated, for example, undera pressure of about 2,000 psig. Vapor comprising substantial amounts ofhydrogen and lesser amounts of hydrogen sulfide is withdrawn from theflash drum 28 by means of the line 30 and is conducted to a compressor32.

A portion of the compressed gas is recycled by means of conduits 34, 36and 18 for admixture with the desulfurization charge stock in conduit 20at a point which is downStream from the heater 16. Thehydrogen-containing recycle gas stream 36 is first heat exchanged withthe desulfurization reactor effluent stream 24 in the heat exchanger 38.This raises the temperature of the untreated recycle gas stream, whichwill not pass through the heater 16, at this point to a temperature, forexample, of about 700 F. When combined with the stream 20, this recyclestream permits control of the temperature of the desulfurization chargestream to that desired for introduction into the desulfurization reactor22.

The amount of untreated recycle gas which is passed by means of conduits36 and 18 back to the desulfurization reactor 22 is suitably in therange of between about 60 and about 90 percent of the total recycle gasof line 30, preferably between about 75 and about 85 percent, with 80percent of the total recycle gas stream being especially preferred. Theremaining portion of recycle gas, which is between about and about 40percent, preferably about to about 25 percent, and most preferably aboutpercent of the total recycle gas stream, is conducted by means of line40 to a cooler 42 where the temperature of the stream is reduced to atemperature below the water dew point and thence to a separator 43wherein water is separated and removed from the system by means of line41. The balance of this portion of the recycle gas is then passed vialine 45 to a hydrogen sulfide removal treatment which may be, forexample, a high pressure liquid absorbent contactor 44. A suitabletreating agent, such as an amine, is introduced into the contactor 44 bymeans of the line 46, preferably in a countercurrent fashion withrespect to the gas stream to be treated. A hydrogen-rich, hydrogensulfidedepleted stream is withdrawn from contactor 44 by means of line48 while a stream of hydrogen sulfide-rich treating agent is removedfrom contactor 44 by means of line 50.

Suitable conditions for the amine contactor 44 include a temperature inthe range between about 70 and about 170 F., preferably 110 and about140 F. Suitable pressures include those in the range of between about250 and about 4,000 psig, preferably between about 500 and about 3,000psig.

The hydrogen-rich, hydrogen sulfide-depleted recycle stream of line 48,after passing through the knock-out drum 52, is recycled for admixturewith the desulfurization charge stock by means of the conduit 14.Entrained portions of amine are withdrawn from the knock-out drum 52 bymeans of the line 54. Sufiicient recycle gas must be contacted in thetreater 44 and recycled for introduction by means of the line 14upstream of the heater 16, so that when the hydrogen recycle gas isadded to the liquid feed along with the make-up hydrogen, coke will notbe produced in the feed heater 16 to a substantial degree.

The amount of hydrogen sulfide-depleted recycle gas that must be addedto the liquid feed upstream of the heater depends upon thesusceptibility of the liquid feed to coke production in the heater 16.Accordingly, a hydrocarbon feed which is highly susceptible to cokeproduction in the heater 16 will require greater amounts of the hydrogensulfide-depleted hydrogen recycle stream than will hydrocarbon chargestocks which are less susceptible to coke formation.

The amine treated recycled gas stream which is admixed with thehydrocarbon feed to the desulfurization treater 22 by means of the line14 can suitably provide between about 500 and about 3,000 standard cubicfeed of hydrogen per barrel of hydrocarbon desulfurization charge stock,preferably between about l,000 and about 2,000 standard cubic feet ofhydrogen per barrel of oil to be treated. As previously discussed, theremainder of the recycled gas stream, i.e., the untreated gas, willbypass the feed heater 16 and be introduced by means of the conduit 18for admixture with the desulfurization charge stock.

In this manner, hydrocarbon removal from the recycle stream isminimized, since only a portion of the recycle gas stream is treated forhydrogen sulfide removal. Normally, when the total recycle gas stream istreated for hydrogen sulfide removal by amine contacting, about percentof the hydrogen sulfide formed during the hydrodesulfurization processis removed and the hydrogen sulfide concentration throughout the entiresystem is maintained at a comparatively low level. In the practice ofthe present invention, however, since only a portion of the recycle gasstream is treated for hydrogen sulfide removal, the overall level ofhydrogen sulfide within the system stabilizes at a comparatively higherlevel, once recycle has commenced. As will be understood, when treatingequal volumes of gas containing hydrogen sulfide, a greater absolutequantity of hydrogen sulfide will be removed from the gas initiallycontaining the higher hydrogen sulfide concentration. Accordingly then,when treating only a portion of the recycle gas stream, e.g., about 20percent of the total, a greater absolute quantity of hydrogen sulfidewill be removed per volume of gas treated than will be removed whentreating the total recycle gas. In the particular instance of treatingonly about 20 percent of the total recycle gas about 45 percent of thehydrogen sulfide formed in the hydrodesulfurization process will beremoved as opposed to 80 percent of the hydrogen sulfide formed whentreating the total recycle gasv Thus, it will be seen that in fact lessgas is treated per mol of hydrogen sulfide removed and since thepotential hydrocarbon inclusion in the hydrogen sulfide removed isdependent solely upon the volume of gas treated, a reduction in thequantity of recycle gas treated inherently results in a reduction in thequantity of hydrocarbons included with the hydrogen sulfide, therebyresulting in a substantially higher ratio of mols of hydrogen sulfideremoved per mol of hydrocarbon removed.

The absorption and entrainment of hydrocarbon in the amine treatingagent along with the hydrogen sulfide cannot be prevented. However, thetemperature of the recycle gas stream is adjusted by means of the cooler42 so that the gas stream of line 45 fed to the treater 44 will be at atemperature which is below its water dew point, as mentioned above, butat or above its hydrocarbon dew point. Additionally, a differential ismaintained between the inlet temperature of the gas stream of line 45 totreater 44 and the inlet temperature of the treating agent of line 46 totreater 44 so that the gas of line 45 is heated as it passes throughtreater 44 and is maintained at a temperature above the hydrocarbon dewpoint. This limits condensation of the heavy hydrocarbons to a largeextent and prevents their removal with the treating agent which isdischarged with the hydrogen sulfide-containing treating agent by meansof line 50 from the bottom of the treater. The hydrogen sulfide-richtreating agent stream that is withdrawn by means of the line 50 ispassed to a regenerator (not shown) for the recovery of the hydrogensulfide from the treating agent. The recovered hydrogen sulfide ispassed to a sulfur plant for the production of sulfur. Since the sulfurby-product has a reduced quantity of hydrocarbons therein, theproduction of a salable sulfur product is made possible.

Referring again to the flash drum 28, a liquid stream 55 is removedtherefrom and is introduced into low pressure flash drum 56 in which thestream 54 is separated into a liquid fraction 58 and a vapor fraction60. The vapor fraction 60 comprises hydrogen and hydrogen sulfide andmay be passed to a hydrogen sulfide removal treatment (not shown) forremoval of hydrogen sulfide and the production of a hydrogen-richrecycle stream. The liquid fraction 58 comprises a desulfurized liquidhydrocarbon fraction which may be further treated for the removal of anyresidual hydrogen sulfide therein (by a means not shown).

Alternatively, the charge stock which is introduced by means of line maybe a high boiling portion of a crude oil which has been prefractionatedto separate a light ends fraction therefrom prior to subjecting theheavy fraction to a desulfurization treatment. In that event, the liquidfraction withdrawn from the low pressure flash drum 56 may be passedfrom the line 58 to a tower, such as a stripper, wherein the hydrogensulfide content thereof is stripped therefrom with hydrogen and theresulting fraction is blended with the previously separated light-endsfraction.

Obviously, the drawing has been greatly simplified so that variouspumps, compressors, heat exchange means, and the like have not beenshown for the sake of simplicity. Thus, where single heat exchange meansand compressors have been indicated, a plurality of such means may besuitably employed.

In the foregoing manner, the process of the present invention permitsthe production of a high purity, salable sulfur byproduct from thehydrogen sulfide while at the same time eliminating severe corrosionproblems in the desulfurization charge stock heater.

This invention may be best understood by reference to the followingspecific example, which is illustrative only and is not intended to belimiting as to scope.

EXAMPLE An arrangement similar to that illustrated in the drawing isemployed for the purposes of this example. A Kuwait crude oil isdesalted and dewatered and is then heated in a fired heater and ispassed to a flash drum at the rate of 44,000 BPSD (barrels per streamclay). The flash drum is operated at a temperature of 600 F. and under apressure of 1 l5 psia, thus resulting in a separation of the crude oilinto a light fraction comprising 24 percent by volume of the total crudefed.

The flashed crude heavy fraction is compressed to the pressure requiredfor desulfurization and is then mixed with a make-up hydrogen streamcomprising 93 percent by volume hydrogen and a recyclehydrogen-containing gas stream that had been amine-treated for theremoval of the hydrogen sulfide. Sufficient recycle gas is amine-treatedso that when joined with the make-up hydrogen there will be providedabout 1,500 standard cubic feet of hydrogen per barrel of flash crudecharge. This amount of recycle hydrogen was considered necessary toprevent excessive coking in the feed heater when processing the flashedKuwait crude fraction.

The mixture of liquid feed and hydrogen is then heated to a maximumtemperature of about 800 F. in a gas-fired heater. At the heater outlet,the hydrogen-charge stock admixture is joined with additional recyclegas that had not been aminetreated for hydrogen sulfide removal. Thisstream comprises about 80 mol percent hydrogen and about 3 mol percenthydrogen sulfide. The untreated recycle gas stream is heat exchangedwith the reactor effluent from a hydrodesulfurization reactor to raiseits temperature and is then admixed with the fired heater effluent. Theaverage temperature at reactor inlet of this combined stream is about750 F.

The hydrocarbon-hydrogen admixture then flows to catalyst guard beds andis passed to a hydrodesulfurization reactor. The reactor is providedwith a nickel-cobalt-molybdenum desulfurization catalyst on an aluminasupport. Other reaction conditions employed in the hydrodesulfurizationreactor are an LHSV of amount 1 and a hydrogen partial pressure of about2,000 psi.

Reactor effluent is withdrawn at a maximum temperature of about 815 F.and is heat exchanged with recycle gas, feed to the hydrodesulfurizationreactor and the crude oil feed. At the outlet of the crude oil feed heatexchange system, the reactor effluent has a temperature of about 350 F.p

The reactor effluent is then cooled to a temperature of 150 F. in anaerial cooler and is passed to a high pressure flash drum which isoperated at a pressure of about 2,400 psia. A gaseous stream comprisingmol percent hydrogen and 3 mol percent hydrogen sulfide is removed fromthe high pressure flash drum and is passed to a compressor where thestream pressure is increased to about 2,700 psia.

Twenty percent by volume of this stream is cooled to a temperature of F.and is passed to an amine contactor wherein this portion of the gasstream is counter-currently contacted with about 9776 BPSD ofethanolamine which is at a temperature of F. The temperatures andpressures are adjusted in the amine contactor so that the treated gas isat a temperature above the hydrocarbon dew point thereby limitingcondensation of heavy hydrocarbons.

Amine-treated gas comprising about 84 mol percent hydrogen andessentially no hydrogen sulfide is recycled for admixture with theliquid hydrocarbon desulfurization charge stock at a point upstream ofthe gas fired heater. Meanwhile, about 80 percent of the untreated andcompressed gas stream is recycled for admixture with the desulfurizationcharge stock at a point downstream of the gas fired heater. The hydrogensulfide removal treatment of about 20 percent of the total recycled gasremoves about 45 percent of the net hydrogen sulfide produced.

The liquid from the high pressure flash drum is passed to a low pressureflash drum which is operated at a pressure of psia. Vapor from the lowpressure flash drum is passed to an amine contactor for removal of thehydrogen sulfide and the purified hydrogen is recovered and employed inthe process. The liquid bottoms from the low pressure flash drumcontains hydrogen sulfide and is passed to the top tray of a syntheticcrude stripper for removal of this impurity. The flashed vapor from theoriginal crude is passed to a lower zone in the stripper and hydrogen isintroduced into the stripper for removal of hydrogen sulfide from thedesulfurized liquid hydrocarbon. in this manner, the flash vapor and thedesulfurized now hydrogen sulfide-depleted liquid hydrocarbon fractionsare combined and are recovered as a desulfurized synthetic crudeproduct.

Obviously, many modifications and variations of the invention ashereinabove set forth may be made without departing from the spirit andscope thereof, and therefore only such limitations should be imposed asare indicated in the appended claims.

We claim:

I. A process for the desulfurization of a sulfur-containing hydrocarbonfraction which comprises:

1. admixing the hydrocarbon fraction with substantially hydrogensulfide-free, hydrogen-containing gas to form a first hydrocarbon-gasmixture, at least a portion of said hydrogen-containing gas beingrecycled from said process, as described hereinafter;

2. preheating said first mixture;

3. admixing said preheated mixture with an effluent gas comprisinghydrogen and hydrogen sulfide to form a second hydrocarbon-gas mixture,said effluent gas being recycled from said process, as describedhereinafter;

4. subjecting said second mixture to a hydrodesulfurization reactionresulting in a desulfurized reaction effluent;

. separating said reaction effluent into a liquid hydrocarbon productand said effluent gas;

6. subjecting a first portion of said effluent gas to a hydrogen sulfideremoval treatment to produce said substantially hydrogen sulfide-free,hydrogen-containing gas and recycling said gas to step (1 7. recycling asecond portion of said effluent gas to form said second hydrocarbon-gasmixture of step (3), and

8. recovering the hydrogen sulfide removed in step (6).

2. The process of claim 1 wherein between about 10 and about 40 percentby volume of the effluent gas is subjected to a hydrogen sulfide removaltreatment.

3. The process of claim 2 wherein about percent by between about toabout F.

6. The process of claim 5 wherein the absorbent is an aminev 7. Theprocess of claim 5 wherein the hydrogen sulfide removal treatment isconducted at a temperature above the hydrocarbon dew point of theeffluent gas.

2. preheating said first mixture;
 2. The process of claim 1 wherein between about 10 and about 40 percent by volume of the effluent gas is subjected to a hydrogen sulfide removal treatment.
 3. The process of claim 2 wherein about 20 percent by volume of the effluent gas is subjected to a hydrogen sulfide removal treatment.
 3. admixing said preheated mixture with an effluent gas comprising hydrogen and hydrogen sulfide to form a second hydrocarbon-gas mixture, said effluent gas being recycled from said process, as described hereinafter;
 4. subjecting said second mixture to a hydrodesulfurization reaction resulting in a desulfurized reaction effluent;
 4. The process of claim 1 wherein the hydrocarbon fraction is preheated to a temperatuRe in the range of between about 500* and about 900* F.
 5. The process of claim 1 wherein the hydrogen sulfide-removal treatment comprises contacting said first portion with an absorbent treating agent at a temperature in the range between about 70* to about 140* F.
 5. separating said reaction effluent into a liquid hydrocarbon product and said effluent gas;
 6. subjecting a first portion of said effluent gas to a hydrogen sulfide removal treatment to produce said substantially hydrogen sulfide-free, hydrogen-containing gas and recycling said gas to step (1);
 6. The process of claim 5 wherein the absorbent is an amine.
 7. The process of claim 5 wherein the hydrogen sulfide removal treatment is conducted at a temperature above the hydrocarbon dew point of the effluent gas.
 7. recycling a second portion of said effluent gas to form said second hydrocarbon-gas mixture of step (3), and
 8. recovering the hydrogen sulfide removed in step (6). 